Deepset receiver for drilling application

ABSTRACT

Drilling telemetry systems and methods include a cable antenna a cable antenna in an auxiliary borehole in a subterranean formation arranged to receive electromagnetic signal transmitted from an EM tool in an adjacent wellbore in the subterranean formation. The cable antenna may include a wireline cable having a center core, an insulated electrical cable head in direct electrical communication with the center core, and an uninsulated signal receiver in direct electrical communication with electrical cable head. The uninsulated signal receiver may have an outer surface formed of a conductive material and configured to contact a natural subterranean formation.

BACKGROUND OF THE DISCLOSURE

The present disclosure relates in general to logging tools andparticularly to receivers used in electromagnetic logging tools.

Measurement-while-drilling (MWD) tools and logging-while-drilling (LWD)tools capture information during the process of drilling a wellbore.However, the ability of current receivers to receive signals using MWDtools typically provide drilling parameter information such as weight onthe bit, torque, temperature, pressure, direction, and inclination. LWDtools typically provide formation evaluation measurements such asresistivity, porosity, and NMR distributions (e.g., T1 and T2). MWD andLWD tools often have characteristics common to wireline tools (e.g.,transmitting and receiving antennas), but MWD and LWD tools must beconstructed to not only endure but to operate in the harsh environmentof drilling.

BRIEF DESCRIPTION OF THE DRAWINGS

The present disclosure is best understood from the following detaileddescription when read with the accompanying figures. It is emphasizedthat, in accordance with the standard practice in the industry, variousfeatures are not drawn to scale. In fact, the dimensions of the variousfeatures may be arbitrarily increased or reduced for clarity ofdiscussion.

FIG. 1 is an illustration of an exemplary drilling telemetry system in asubterranean formation according to one or more aspects of the presentdisclosure.

FIG. 2 is an illustration of a cross-sectional view of an exemplaryelectromagnetic tool of the telemetry system of FIG. 1 according to oneor more aspects of the present disclosure.

FIG. 3 is an illustration of a cross-sectional view exemplary signalreceiving system of the telemetry system of FIG. 1 according to one ormore aspects of the present disclosure.

FIG. 4 is an illustration of a perspective view of the exemplary signalreceiver according to one or more aspects of the present disclosure.

FIG. 5 is a flow chart diagram of at least a portion of a methodaccording to one or more aspects of the present disclosure.

DETAILED DESCRIPTION

It is to be understood that the following disclosure provides manydifferent embodiments, or examples, for implementing different featuresof various embodiments. Specific examples of components and arrangementsare described below to simplify the present disclosure. These are, ofcourse, merely examples and are not intended to be limiting. Inaddition, the present disclosure may repeat reference numerals and/orletters in the various examples. This repetition is for the purpose ofsimplicity and clarity and does not in itself dictate a relationshipbetween the various embodiments and/or configurations discussed.Moreover, the formation of a first feature over or on a second featurein the description that follows may include embodiments in which thefirst and second features are formed in direct contact, and may alsoinclude embodiments in which additional features may be formedinterposing the first and second features, such that the first andsecond features may not be in direct contact.

This disclosure is directed to an improved system and method forobtaining downhole information during a well drilling process. In someimplementations, the system and method employ a transmitting element ona drill string that communicates electromagnetic signals throughsubterranean formations to a receiver disposed in a separate auxiliaryborehole. The receiver may be particularly arranged to detect andreceive signals, even weak signals, passed through the subterraneanformation. In this implementation, the receiver is particularly designedwithout exterior material that may insulate or dampen signals that maybe received through the subterranean formation. That is, in someexemplary implementations, the receiver comprises a conductive materialforming an external surface of the receiver and disposed in directcontact with the subterranean formation. In addition, the conductivematerial may be in direct communication with a center core or wireforming a portion of the wireline cable. Signal processing may occur atthe surface.

FIG. 1 shows an example of a drilling telemetry system 100 for signalingin a subterranean formation. In this implementation, the drillingtelemetry system 100 is formed of a drilling rig system 102 and a signalreceiving system 104. The drilling rig system 102 includes, among othercomponents, a transmitter, and the signal receiving system 104 includes,among other components, a receiver. The drilling rig system 102 mayelectromagnetically communicate information to the receiving system 104.For example, the drilling rig system 102 may transmit information, suchas information relating to the status of the drilling rig system 102,the wellbore, or other information to the receiving system 104. In otherexamples, the drilling rig system 102 may emit electromagnetic signalsthat may be captured by the receiving system 104 that may allow thereceiving system 104 to detect geological formation characteristics orother information relating to the geographic material through which thesignals are transmitted.

The drilling rig system 102 may be, for example, a land-based drillingrig system—however, one or more aspects of the present disclosure areapplicable or readily adaptable to any type of drilling rig system(e.g., a jack-up rig, a semisubmersible, a drill ship, a coiled tubingrig, a well service rig adapted for drilling and/or re-entry operations,and a casing drilling rig, among others). The drilling rig system 102includes a mast 106 that supports lifting gear above a rig floor 108,which lifting gear may include a crown block and a traveling block. Thecrown block may be disposed at or near the top of the mast 106. Thetraveling block may hang from the crown block by a drilling line. Thedrilling line may extend at one end from the lifting gear to drawworks,which drawworks are configured to reel out and reel in the drilling lineto cause the traveling block to be lowered and raised relative to therig floor 108.

In some implementations, the drilling rig system 102 may include a topdrive 110 suspended from the bottom of the traveling block. A drillstring 112 may be suspended from the top drive 110 and suspended withina wellbore 113.

The drill string 112 may include interconnected sections of drill pipe114, a bottom-hole assembly (“BHA”) 116, and a drill bit 118. The BHA116 may include stabilizers, drill collars, and/ormeasurement-while-drilling (“MWD”) or wireline conveyed instruments,among other components. The drill bit 118 (also be referred to herein asa tool) is connected to the bottom of the BHA 116 or is otherwiseattached to the drill string 112.

The downhole MWD or wireline conveyed instruments may be configured forthe evaluation of physical properties such as pressure, temperature,torque, weight-on-bit (“WOB”), vibration, inclination, azimuth, toolfaceorientation in three-dimensional space, and/or other downholeparameters. These measurements may be made downhole, stored insolid-state memory for some time, and downloaded from the instrument(s)at the surface and/or transmitted real-time to the surface. In theimplementations described herein, data may be transmittedelectromagnetic pulses. In some implementations, in addition totransmission capability, the MWD tools and/or other portions of the BHA116 may have the ability to store measurements for later retrieval viawireline and/or when the BHA 116 is tripped out of the wellbore 113.

In the embodiment of FIG. 1, the top drive 110 is utilized to impartrotary motion to the drill string 112. However, aspects of the presentdisclosure are also applicable or readily adaptable to implementationsutilizing other drive systems, such as a power swivel, a rotary table, acoiled tubing unit, a downhole motor, and/or a conventional rotary rig,among others.

The drilling rig system 102 also includes a control system 120configured to control or assist in the control of one or more componentsof the drilling rig system 102—for example, the control system 120 maybe configured to transmit operational control signals to a drawworks,the top drive 110, the BHA 116 and/or additional equipment. In someembodiments, the control system 120 includes one or more systems locatedin a control room proximate the drilling rig system 102, such as thegeneral purpose shelter often referred to as the “doghouse” serving as acombination tool shed, office, communications center, and generalmeeting place. The control system 120 may be configured to transmit theoperational control signals to the drawworks, the top drive 110, the BHA116, and/or other equipment via wired or wireless transmission (notshown). The control system 120 may also be configured to receiveelectronic signals via wired or wireless transmission (also not shown)from a variety of sensors included in the drilling rig system 102, whereeach sensor is configured to detect an operational characteristic orparameter. Some example sensors from which the control system 120 isconfigured to receive electronic signals via wired or wirelesstransmission (not shown) may include one or more of the following: atorque sensor, a speed sensor, and a WOB sensor. In someimplementations, the BHA 116 may also include sensors disposed thereon.Some exemplary sensors include for example, a downhole annular pressuresensor 122 a, a shock/vibration sensor 122 b, a toolface sensor 122 c, aWOB sensor 122 d, a surface casing annular pressure sensor 124, a mudmotor delta pressure (“ΔP”) sensor 126 a, and one or more torque sensors126 b. The sensors are merely examples of any of a variety of sensorsthat may be included on the BHA 116, the drill bit 118, and/or otherwisedisposed about the drilling rig system 102.

In this exemplary embodiment, the BHA 116 also includes an EM tool 130.The EM tool 130 may be configured to propagate an electromagnetic signalto convey information from the BHA for receipt and analysis by drillingrig personnel. Although identified as a part of the BHA 116, in someimplementations, the EM tool 130 is disposed elsewhere along the drillstring 112 and down in the wellbore 113. Some implementations includemultiple EM tools 130 arranged to propagate a signal through thesubterranean formations. The EM tool 130 may form a part of themeasurement while drilling MWD tool. In some implementations, the EMtool 130 may form a part of a collar or stabilizer of the drill string.Some implementations of the EM tool 130 feature 2-way EM communication,while other implementations include only transmission capability. Insome implementations, the power, the data rate, and the carrier wave maybe adjustable while drilling to help transmit through changingformations. In some implementations, the EM tool may operate usingbatteries or a turbine alternator. The turbine alternator may enablelonger downhole times, and higher transmitting power for longer periods.Some implementations may include backup batteries for operation duringperiods of no flow.

FIG. 2 shows an example of an EM tool 130 that may form a part of theBHA 116. The EM tool 130 may include an electrode 131, a downlinkreceiver 132, a transmitter 133, and the power source 134, such asbatteries. The electrode 131 may enable the EM tool 130 to communicatewith other downhole systems such as, for example, sensing systems thatmay be carried on the BHA. The downlink receiver 132 may be configuredto receive signals and information from the surface, from other EMtools, or other equipment that may be in communication with the EM tool130. The transmitter 133 transmits EM signals through geologicalformations. In some implementations, the transmitter 133 is ahigh-voltage transmitter configured to automatically select thenecessary power usage for the formation resistance. This may help extendthe life of the power source 134 by reducing the need to transmit atfull power in certain situations.

Returning to FIG. 1, the signal receiving system 104 may be disposed inan auxiliary borehole 138. The signal receiving system 104 may include acable antenna 140 and a signal processing system 142. In theimplementation shown, the cable antenna 140 includes a wireline cable144, an electrical cable head 146, and a signal receiver 148. In thisexample, the wireline cable 144 may extend or be wound around a cablecoil or reel 150 disposed on steerable equipment, such as a workingvehicle 152, such as a truck. In the deployed configuration shown, thewireline cable 144 may extend from the cable coil 150 through a borehead 154, and into the auxiliary borehole 138.

FIG. 3 shows a cross-section of a portion of the signal receiving system104, including a portion of the wireline cable 144, the electrical cablehead 146, and the signal receiver 148. The wireline cable 144 mayinclude a center core 160, a polymer jacket 162 surrounding the centercore 160, and a protective or armor layer 164 disposed about the polymerjacket 162. The center core 160 may be formed of a conductive materialand may extend the length of the wireline cable 144. The center core 160may be configured to communicate signals from the electrical cable head146 and the signal receiver 148 to the processing system 142. In someexamples, the polymer jacket is a polytetrafluoroethylene (PTFE)material, and in some implementations, the polymer jacket is or includesTEFLON® material. The polymer jacket 162 may insulate or isolate thecenter core 160 from the armor layer 164. The protective or armor layer164 may be formed of any material that provides protection and strengthto the wireline cable 144. For example, it may comprise a metal ormetal-clad, hollow cable that provides sufficient tensile strength tothe wireline cable 144. It may be formed of a plurality of braided wiresor otherwise formed. It may be metal or some other material, includingnon-conductive materials. It may be designed to carry the weight ofelectrical cable head 146 and the signal receiver 148. The armor layer164 may form the outer surface of the wireline cable 144. In someimplementations, the armor layer is a steel armor layer.

The electrical cable head 146 may be disposed between the wireline cable144 and the signal receiver 148. It may electrically connect the centercore 160 to the conductive material of the signal receiver 148. In someimplementations, electrical cable head 146 may include a housing 168, anelectrical conductor 170, and a cable anchor 172. The housing 168extends from a proximal end 174 to a distal end 176. The proximal end174 may include an opening 178 through which the wireline cable 144 mayextend. The opening 178 may lead to an anchor cavity 180 incommunication with a passage 182. The distal end 176 of the housing 168may include a threaded tip 184.

The electrical conductor 170 may be in electrical communication with thecenter core 160 of the wireline cable 144. In some implementations, theelectrical conductor 170 may extend in the passage 182 from the proximalend 174 to the distal end 176 and may terminate at the threaded tip 184.In some implementations, the electrical conductor 170 comprises aspring-loaded contact 186 projecting from the distal end 176 thatcontacts the signal receiver 148.

The cable anchor 172 may be disposed within the anchor cavity 180 andmay be connected to the wireline cable 144. In some implementations, thecable anchor 172 is attached to the armor layer 164 of the wirelinecable 144. In some implementations, the center core 160 is electricallyconnected with the electrical conductor 170 through the cable anchor172. Some implementations include an insulative cover about theelectrical conductor 170. The insulative cover may be for example aceramic or polymeric material that prevents electrical communicationbetween the electrical conductor 170 and the housing 168.

The signal receiver 148 is connected to the distal end 176 of thehousing 168. The signal receiver 148 may be formed of a heavy,conductive material. In some implementations, the signal receiver 148 isformed of a solid stainless steel material. In other implementations,the signal receiver 148 is formed of copper, silver, or other highlyconductive material and with features aiding deployment and contact withformation or casing it is deployed in. In the implementation shown, thesignal receiver 148 is formed of a solid bulbous head 190 with sides 192that taper toward the housing 168, forming a frustum. A threaded bore orthreaded cavity 194 is disposed in the end of the frustum and receivesthe threaded tip 184 of the housing 168. The signal receiver 148 isformed to abut in direct contact with the walls or sides of theauxiliary borehole 138 (FIG. 1) through which it is introduced.Accordingly, the signal receiver 148 is in contact with the naturalgeological formation of the auxiliary borehole 138. In some embodiments,signal receiver 148 may contact the hole casing in case of cased holes.As such, the signal receiver 148 also acts as the signal receiver fromthe EM tool 130. Because the signal receiver 148 is in direct contactwith the subterranean formation, the signal receiver 148 is configuredand arranged to receive EM signals from the EM tool 130 withoutinterference or dampening from unnatural components about the signalreceiver 148. For example, the signal receiver 148 is free of insulativeor protective materials that may interfere or dampen reception ofsignals. Also, it is deployed deeper relative to a conventional EMantenna at the surface which is prone to signal attenuation for longreach wells and signal loss in case of salt domes in certain basins.Because of this, the signal receiver 148 may be particularly sensitiveto even weak signals emitted from the EM tool 130 and propagated throughthe subterranean formation. Furthermore, the electrically conductiveouter surface (the exterior surface) of the signal receiver 148 is indirect electrical communication with the electrical conductor 170 of thecable anchor 172, and with the center core 160 of the wireline cable144. This electrical connection may be free of filtering or other signaldistorting components so that the signal communicated to the groundsurface is the complete and natural signal received at the signalreceiver 148.

In this implementation, the shape of the signal receiver 148 maycontribute to the receptivity of the EM signals. For example, thebulbous head, having a diameter greater than the diameter of theelectrical cable head 146 insures that a significant portion of thesignal receiver 148 is in contact with the natural subterraneanformation. In the implementation shown, the signal receiver 148 has thelargest cross-sectional diameter of any of the wireline cable 144 or theelectrical cable head 146. This may help increase the likelihood thatthe signal receiver 148 will be in contact with the subterraneanformation whether disposed in a vertical auxiliary borehole or in acurved or a horizontal auxiliary borehole.

FIG. 4 shows a perspective view of an example of a signal receiver 148.The signal receiver 148 in this implementation includes a roundedleading end 196 and a trailing end 198. The tapering sides 192 tapertoward the trailing end 198. In this implementation, the signal receiver148 has a substantially teardrop-shape, with the rounded leading end 196forming the large diameter bulbous head. A notch 199 may be formed in aside to enable the signal receiver 148 to be grasped by a tool forthreading onto the electrical cable head 146. In some implementations,the signal receiver 148 has a diameter in the range of about 2 to 12inches, and has a length in a range of about 3 to 18 inches, althoughlarger and smaller diameters and lengths are contemplated. In someimplementations, the signal receiver 148 has a diameter in the range ofabout 2 to 4 inches and has a length in the range of about 4 to 8inches. Furthermore, the rigidity of the bulbous signal receiver reducesthe likelihood of hang-up when the signal receiver 148 is introduced andfed through the auxiliary borehole 138. For example, a loose cable orother flexible component at the distal end may interfere withadvancement of the signal receiving system 104.

In some implementations, an insulative covering may isolate the signalreceiver 148 from the housing 168 of the electrical cable head 146. Insuch implementations, the signal receiver 148 is still in electricalcommunication with the electrical conductor 170 projecting from thethreaded tip 184 of the housing 168. In some implementations, theelectrical conductor 170 is the only component in electricalcommunication with the signal receiver 148.

The signal processing system 142 may be disposed at the surface adjacentthe bore hole and may be configured to receive and process signalsdetected or received at the signal receiver 148. In someimplementations, the processing system 142 is in direct communicationwith the center core 160 of the wireline cable 144. Accordingly, signalsdetected at the signal receiver 148 may be communicated through theelectrical cable head 146 and the wireline cable 144 to the processingsystem 142. In some implementations, the processing system 142 is acomputer having software configured to interpret EM signals receivedfrom the EM tool 130.

Because the signal receiver 148 is able to directly contact thesubterranean formations, and there is no isolation or insulativeelements between the signal receiver 148 and the center core 160, EMsignals may be more easily received and captured for processing. Thecable antenna 140 implementation shown in FIG. 3 may be a retrievabletype and may be easily deployable by means of coil tubing or wireline orthe center conductor can be isolated or connected to the polymericmaterial. In some implementations, this receiver may be used for amultitude of wells being drilled across the pad as well as nearby pads.In some implementations, the wireline cable 144, the electrical cablehead 146, and the signal receiver 148 form a simple conductiveconnection having no control feedback or logic system. It may receiveand relay the signal to the surface. In some implementations, the systemdoes not require electric/magnetic isolation between the center core andthe polymeric jacket. Furthermore, in some implementations, the systemdoes not require insulation between the signal receiver 148, theelectrical conductor 170, and the center core 160.

FIG. 5 is a flow diagram showing a process of using the drillingtelemetry system 100 according to an exemplary implementation. At 502, auser may introduce the EM tool 130 to the wellbore. The EM tool 130 mayform a part of or be disposed adjacent to a BHA during a drillingoperation carried out by the drilling rig system 102. In someimplementations, the EM tool 130 may be spaced apart from the BHA, butmay be downhole in the subterranean formation.

At 504, a user may introduce the signal receiving system to an auxiliaryborehole. Because of the size and shape of the signal receiver 148, thesignal receiver may be in direct contact with the natural subterraneanformation. That is, because the signal receiver 148 forms the distalmost tip of the signal receiving system, and because the signal receiver148 may, in some implementations, have a diameter larger than othercomponents around the signal receiver 148, the signal receiver 148 maybe in direct contact with the natural subterranean formation. Since thesignal receiver 148 is also un-insulated, EM signals propagated throughthe subterranean formation may be detected or picked up directly fromthe subterranean formation without interference or dampening frominsulative or isolating materials other than the natural subterraneanformation. The signal receiving system 104 may be introduced to theauxiliary borehole with the electrical cable head 146 and the signalreceiver 148 suspended from the wireline cable 144. The signal receiverand the electrical cable head 146 each include direct electrical contactwith each other.

At 506, the EM tool 130 may transmit EM signals through the subterraneanformation. The signals may relate to detected parameters of the wellboreand its surrounding environment, of the drilling equipment, or of thesubterranean formation. Accordingly, the transmitted EM signals mayinclude MWD or LWD information. The EM signals may be transmitted whileactual drilling is occurring, or may be transmitted during down times ofthe drilling process, such as when stands are being introduced to thedrill string or during other stoppages in actual drilling.

At 508, the signal receiver 148 may detect the EM signals directly fromthe subterranean formation. Since the signal receiver 148 isparticularly shaped to provide a large amount of surface contact area,as well as have a wider diameter than other components of the downholesignal receiving system, the signal receiver 148 may receive signalsleft otherwise undetected by conventional telemetry systems. In someimplementations, the EM signals are received only at the signalreceiver. In such implementations, the electrical cable head 146 and thewireline cable 144 may include insulative or protective materialsdisposed about their respective conductive portions that may inhibitreception of EM signals transmitted or propagated through thesubterranean formation.

At 510, the detected signals may be communicated directly from thesignal receiver through the electrical cable head 146 and the wirelinecable 144 to the processing system 142. Since the signal receiver is indirect electrical communication with the electrical conductor of theelectrical cable head 146, and since the electrical conductor 170 is indirect electrical communication with the center core 160 of the wirelinecable 144, signals may be communicated directly to the processing system142, even when the processing system 142 is disposed above ground. At512, the processing system 142 may interpret the signals at the surface.

In an exemplary aspect, the present disclosure is directed to a drillingtelemetry system that may include an EM tool sized and configured to bedisposed on a drill string and introduced into a wellbore in asubterranean formation. The EM tool may comprise a transmitterconfigured to transmit an electromagnetic signal through thesubterranean formation. The drilling telemetry system may also include acable antenna sized and configured to be introduced into an adjacentauxiliary borehole in the subterranean formation and arranged to receivethe electromagnetic signal transmitted from the EM tool. The cableantenna may comprise a wireline cable having a center core, an insulatedelectrical cable head in direct electrical communication with the centercore, and an uninsulated signal receiver in direct electricalcommunication with electrical cable head. The uninsulated signalreceiver may have an outer surface formed of a conductive material andconfigured to engage against a natural subterranean formation.

In some aspects, the uninsulated signal receiver has a teardrop shapeforming a bulbous head. In some aspects, the uninsulated signal receivercomprises a threaded cavity formed therein for receiving a portion ofthe electrical cable head. In some aspects, the cable antenna comprisesa polymeric jacket around the center core, and a protective layerdisposed around the polymeric jacket. In some aspects, the armor layeris embedded within and fixedly attaches the insulated electrical cablehead to the cable. In some aspects, the conductive material of theuninsulated signal receiver comprises stainless steel. In some aspects,the EM tool comprises a transmitter and a power source. In some aspects,the uninsulated signal receiver has a diameter of about 2 to about 12inches, and a length of about 3 to about 18 inches.

In an exemplary implementation, a method of using a drilling telemetrysystem may include introducing an EM tool to a wellbore; introducing asignal receiving system to an adjacent auxiliary borehole; transmittingan EM signal from the EM tool in the wellbore; detecting the transmittedEM signal with the signal receiver having a conductive exterior surfacein direct contact with walls of the auxiliary borehole, the conductiveexterior surface being in direct electrical communication with anelectrical cable head and a wireline cable; and communicating thedetected EM signal to a signal processing system in communication withthe wireline cable.

In some aspects, detecting the transmitted EM signal with the signalreceiver comprises detecting the transmitted EM signal only at thesignal receiver. In some aspects, the method may include performing adrilling operation, and wherein transmitting the EM signal from the EMtool occurs during the drilling operation. In some aspects, the methodmay include insulating or isolating a conductive center core in thewireline cable and a conductor in the electrical cable head from contactwith the walls of the auxiliary borehole. In some aspects, communicatingthe detected EM signal comprises communicating the detected EM signalthrough a conductor in the electrical cable head and through aconductive center core of the wireline cable. In some aspects, theexterior surface of the signal receiver is in direct conductiveelectrical communication with the conductor in the electrical cablehead. In some aspects, the method may include threading the signalreceiver on to a distal end of the electrical cable head to place aspring-loaded contact in electrical communication with the signalreceiver. In some aspects, the uninsulated signal receiver has ateardrop shape forming a bulbous head. In some aspects, transmitting anEM signal comprises transmitting an EM signal representative of one ormore detected parameters of the wellbore, an environment surrounding thewellbore, of the drilling equipment, of the subterranean formation, or acombination thereof.

In an exemplary aspect, the present disclosure is directed to a drillingtelemetry system that includes an EM tool sized and configured to bedisposed on a drill string and introduced into a wellbore in asubterranean formation. The EM tool may include a transmitter configuredto transmit an electromagnetic signal through the subterraneanformation. The drilling telemetry system may also include a cableantenna sized and configured to be introduced into an adjacent auxiliaryborehole in the subterranean formation and to receive theelectromagnetic signal transmitted from the EM tool. The cable antennamay include a wireline cable having a center core, a polymericinsulative layer disposed about the center core, and an outer protectivelayer disposed about the polymeric insulative layer. The cable antennaalso may include an electrical cable head having a housing, anelectrical conductor in electrical communication with the center core ofthe wireline and extending through the housing, and a cable anchorattached to the outer protective layer and configured to secure theelectrical cable head to the wireline cable. The housing may have adistal end having a spring-loaded contact. The cable antenna also mayinclude an uninsulated signal receiver disposed at a distal-most end ofthe cable antenna and formed of a rigid, conductive material having adiameter of about 2 to about 12 inches. The uninsulated signal receivermay have a conductive outer surface exposed to engage against a naturalsubterranean formation when the cable antenna is disposed in borehole.The uninsulated signal receiver may be in direct electricalcommunication with the spring-loaded contact to provide uninterruptedelectrical communication between the conductive outer surface and theelectrical conductor of the electrical cable head.

In some aspects, the uninsulated signal receiver has a teardrop shapeforming a bulbous head. In some aspects, the uninsulated signal receivercomprises a threaded cavity formed therein for receiving a portion ofthe electrical cable head.

In several exemplary embodiments, the elements and teachings of thevarious illustrative exemplary embodiments may be combined in whole orin part in some or all of the illustrative exemplary embodiments. Inaddition, one or more of the elements and teachings of the variousillustrative exemplary embodiments may be omitted, at least in part,and/or combined, at least in part, with one or more of the otherelements and teachings of the various illustrative embodiments.

Any spatial references such as, for example, “upper,” “lower,” “above,”“below,” “between,” “bottom,” “vertical,” “horizontal,” “angular,”“upwards,” “downwards,” “side-to-side,” “left-to-right,”“right-to-left,” “top-to-bottom,” “bottom-to-top,” “top,” “bottom,”“bottom-up,” “top-down,” etc., are for the purpose of illustration onlyand do not limit the specific orientation or location of the structuredescribed above.

In several exemplary embodiments, while different steps, processes, andprocedures are described as appearing as distinct acts, one or more ofthe steps, one or more of the processes, and/or one or more of theprocedures may also be performed in different orders, simultaneouslyand/or sequentially. In several exemplary embodiments, the steps,processes and/or procedures may be merged into one or more steps,processes and/or procedures.

In several exemplary embodiments, one or more of the operational stepsin each embodiment may be omitted. Moreover, in some instances, somefeatures of the present disclosure may be employed without acorresponding use of the other features. Moreover, one or more of theabove-described embodiments and/or variations may be combined in wholeor in part with any one or more of the other above-described embodimentsand/or variations.

Although several exemplary embodiments have been described in detailabove, the embodiments described are exemplary only and are notlimiting, and those skilled in the art will readily appreciate that manyother modifications, changes and/or substitutions are possible in theexemplary embodiments without materially departing from the novelteachings and advantages of the present disclosure. Accordingly, allsuch modifications, changes and/or substitutions are intended to beincluded within the scope of this disclosure as defined in the followingclaims. In the claims, any means-plus-function clauses are intended tocover the structures described herein as performing the recited functionand not only structural equivalents, but also equivalent structures.

The foregoing outlines features of several embodiments so that a personof ordinary skill in the art may better understand the aspects of thepresent disclosure. Such features may be replaced by any one of numerousequivalent alternatives, only some of which are disclosed herein. One ofordinary skill in the art should appreciate that they may readily usethe present disclosure as a basis for designing or modifying otherprocesses and structures for carrying out the same purposes and/orachieving the same advantages of the embodiments introduced herein. Oneof ordinary skill in the art should also realize that such equivalentconstructions do not depart from the spirit and scope of the presentdisclosure, and that they may make various changes, substitutions andalterations herein without departing from the spirit and scope of thepresent disclosure.

The Abstract at the end of this disclosure is provided to comply with 37C.F.R. § 1.72(b) to allow the reader to quickly ascertain the nature ofthe technical disclosure. It is submitted with the understanding that itwill not be used to interpret or limit the scope or meaning of theclaims.

Moreover, it is the express intention of the applicant not to invoke 35U.S.C. § 112, paragraph 6 for any limitations of any of the claimsherein, except for those in which the claim expressly uses the word“means” together with an associated function.

What is claimed is:
 1. A drilling telemetry system comprising: anelectromagnetic (EM) tool sized and configured to be disposed on a drillstring and introduced into a wellbore in a subterranean formation, theEM tool comprising a transmitter configured to transmit anelectromagnetic signal through the subterranean formation; and a cableantenna sized and configured to be introduced into an adjacent auxiliaryborehole in the subterranean formation and arranged to receive theelectromagnetic signal transmitted from the EM tool, the cable antennacomprising: a wireline cable having a center core; an electrical cablehead having a housing, an electrical conductor in direct electricalcommunication with the center core of the wireline cable and extendingaround a distal-most portion of the center core; and an uninsulatedsignal receiver comprising an outer surface formed from a rigid,conductive material, the uninsulated signal receiver disposed at adistal-most end of the electrical cable head, the uninsulated signalreceiver in direct electrical communication with the electrical cablehead to provide uninterrupted electrical communication between theconductive outer surface and the electrical conductor of the electricalcable head, the uninsulated signal receiver being exposed to engageagainst the subterranean formation when the cable antenna is disposed inthe adjacent auxiliary borehole.
 2. The drilling telemetry system ofclaim 1, wherein the uninsulated signal receiver has a teardrop shapeforming a bulbous head.
 3. The drilling telemetry system of claim 1,wherein the uninsulated signal receiver further comprises a threadedcavity formed therein for receiving a portion of the electrical cablehead.
 4. The drilling telemetry system of claim 1, wherein the cableantenna further comprises a polymeric jacket around the center core, anda protective layer disposed around the polymeric jacket.
 5. The drillingtelemetry system of claim 4, wherein the protective layer is embeddedwithin and fixedly attaches the electrical cable head to the wirelinecable.
 6. The drilling telemetry system of claim 1, wherein theconductive material of the uninsulated signal receiver comprisesstainless steel.
 7. The drilling telemetry system of claim 1, whereinthe EM tool further comprises a power source.
 8. The drilling telemetrysystem of claim 1, wherein the uninsulated signal receiver has adiameter of 2 to 12 inches, and a length of 3 to 18 inches.
 9. A methodof using a drilling telemetry system comprising: introducing anelectromagnetic (EM) tool to a wellbore, the EM tool sized andconfigured to be disposed on a drill string, the EM tool comprising atransmitter configured to transmit an electromagnetic signal through asubterranean formation; introducing a signal receiving system comprisingan uninsulated signal receiver, an electrical cable head, and a wirelinecable to an adjacent auxiliary borehole; transmitting the EM signal fromthe EM tool in the wellbore; detecting the transmitted EM signal withthe uninsulated signal receiver disposed at a distal-most end of thesignal receiving system, the uninsulated signal receiver having aconductive exterior surface in direct contact with walls of theauxiliary borehole, the conductive exterior surface being in directelectrical communication with a distal-most end of the electrical cablehead to provide uninterrupted electrical communication between theconductive exterior surface and an electrical conductor of theelectrical cable head, the electrical cable head being in directelectrical communication with a distal-most end of the wireline cable;and communicating the detected EM signal to a signal processing systemin communication with the wireline cable.
 10. The method of claim 9,wherein said detecting the transmitted EM signal with the signalreceiver comprises said detecting the transmitted EM signal only at thesignal receiver.
 11. The method of claim 9, further comprisingperforming a drilling operation, and wherein said transmitting the EMsignal from the EM tool occurs during the drilling operation.
 12. Themethod of claim 9, further comprising insulating or isolating aconductive center core in the wireline cable and the electricalconductor in the electrical cable head from contact with the walls ofthe auxiliary borehole.
 13. The method of claim 9, wherein saidcommunicating the detected EM signal comprises said communicating thedetected EM signal through the electrical conductor in the electricalcable head and through a conductive center core of the wireline cable.14. The method of claim 9, wherein the exterior surface of the signalreceiver is in direct conductive electrical communication with theelectrical conductor in the electrical cable head.
 15. The method ofclaim 9, further comprising threading the signal receiver on to thedistal-most end of the electrical cable head to place a spring-loadedcontact in electrical communication with the signal receiver.
 16. Themethod of claim 9, wherein the signal receiver has a teardrop shapeforming a bulbous head.
 17. The method of claim 9, wherein saidtransmitting the EM signal comprises said transmitting the EM signalrepresentative of one or more detected parameters of the wellbore, anenvironment surrounding the wellbore, of drilling equipment, of thesubterranean formation, or a combination thereof.
 18. A drillingtelemetry system comprising: an electromagnetic (EM) tool sized andconfigured to be disposed on a drill string and introduced into awellbore in a subterranean formation, the EM tool comprising atransmitter configured to transmit an electromagnetic signal through thesubterranean formation; and a cable antenna sized and configured to beintroduced into an adjacent auxiliary borehole in the subterraneanformation and to receive the electromagnetic signal transmitted from theEM tool, the cable antenna comprising: a wireline cable having a centercore, a polymeric insulative layer disposed in the center core, and anouter protective layer disposed in the polymeric insulative layer; anelectrical cable head having a housing, an electrical conductor inelectrical communication with the center core of the wireline cable andextending through the housing, and a cable anchor attached to the outerprotective layer and configured to secure the electrical cable head to adistal-most end of the wireline cable, the housing having a distal endhaving a spring-loaded contact; and an uninsulated signal receiverdisposed at a distal-most end of the cable antenna and formed of arigid, conductive material having a diameter of 2 to 12 inches, theuninsulated signal receiver having a conductive outer surface exposed toengage against the subterranean formation when the cable antenna isdisposed in the adjacent auxiliary borehole, the uninsulated signalreceiver being in direct electrical communication with the spring-loadedcontact to provide uninterrupted electrical communication between theconductive outer surface and the electrical conductor of the electricalcable head.
 19. The drilling telemetry system of claim 18, wherein theuninsulated signal receiver has a teardrop shape forming a bulbous head.20. The drilling telemetry system of claim 18, wherein the uninsulatedsignal receiver further comprises a threaded cavity formed therein forreceiving a portion of the electrical cable head.